Ryan Smith - Plains All American Pipeline LP Greg L. Armstrong - Plains All American Pipeline LP Harry N.

Pefanis - Plains All American Pipeline LP Alan P. Swanson - Plains All American Pipeline LP

Brian J. Zarahn - Barclays Capital, Inc.

Steve C. Sherowski - Goldman Sachs & Co.

Jeremy B. Tonet - JPMorgan Securities LLC John Edwards - Credit Suisse Securities (USA) LLC (Broker) Sunil K.

Sibal - Seaport Global Securities LLC James M. Jampel - HITE Hedge Asset Management LLC Charles Marshall - Capital One Securities, Inc.

Thanks, Trisha. Good morning, and welcome to Plains All American Pipeline's first quarter 2015 results conference call.

The slide presentation for today's call is available under the Investor Relations section of our website at www.plainsallamerican.com. In addition to reviewing recent results, we will provide forward-looking comments on PAA's outlook for the future.

In order to avail ourselves of Safe Harbor precepts that encourage companies to provide this type of information, we direct you to the risks and warnings included in our latest filings with the Securities and Exchange Commission. Today's presentation will also include references to non-GAAP financial measures, such as adjusted EBITDA.

A reconciliation of these non-GAAP financial measures to the most comparable GAAP financial measures can be found under the financial information tab of the Investor Relations section of our website. Today's presentation will also include selected financial information of Plains GP Holdings, or PAGP.

PAGP consolidates the results of PAA and PAA's General Partner into its financial statements. Accordingly, we do not intend to cover PAGP's results separately from PAA's.

Instead, we have included a schedule in the Appendix to the slide presentation for today's call that reconciles PAGP's distributions received from PAA's General Partner with the distributions paid to PAGP's shareholders and a condensed consolidated balance sheet. Today's call will be chaired by Greg Armstrong, Chairman and CEO.

Also participating in the call are Harry Pefanis, President and COO; and Al Swanson, Executive Vice President and CFO. In addition to these gentlemen and myself, we have several other members of our senior management team present and available for the question-and-answer session.

With that, I'll turn the call over to Greg.

Thanks, Ryan. Good morning, and welcome to all.

Yesterday, PAA reported solid first quarter results coming in $12 million above the high-end of our quarterly guidance. Additionally, we issued operating and financial guidance for the year that essentially reaffirms the guidance we issued in February.

Adjusted EBITDA for the first quarter of 2015 was $622 million, which was approximately $42 million or 7.2% above the mid-point of our guidance. Slide three contains comparisons of various performance metrics to the same quarter of last year, as well as our first quarter 2015 guidance.

Slide four highlights that this is the 53rd consecutive quarter PAA has delivered results in line with or above guidance. For the first quarter of 2015, PAA declared a distribution of $0.685 per limited partner unit, or $2.74 per unit on an annualized basis which will be paid next week.

This distribution represents an 8.7% increase over PAA's distribution paid in the same quarter last year and a 1.5% increase over PAA's distribution paid last quarter. Distribution coverage for the quarter on a standalone basis was 114%.

PAA has now increased its distribution in 42 quarters out of the past 44 quarters and consecutively in each of the last 23 quarters. PAGP declared a quarterly distribution of $0.222 per share which represents a 30.2% increase over the quarterly distribution paid to the same quarter last year and a 9.4% increase over the distribution paid last quarter.

Let me now turn to guidance and our industry outlook. Yesterday, we reduced the upper end of our full-year guidance for adjusted EBITDA by 2%, which shifted the guidance mid-point down by $25 million or 1% from $2.35 billion to $2.325 billion.

As is typically the case, our adjusted EBITDA build up includes a number of ups and downs among PAA's various assets and activities, which mostly offset each other. However, the largest driver for the full year mid-point adjustment was that we changed our model to incorporate the foreign exchange rate for the Canadian and U.S.

dollar of $1.25 to $1. At the beginning of 2015, the FX rate was around $1.15 and in the weeks leading up to our February 5 conference call, the FX rate increased quite a bit ranging from $1.16 to $1.28.

The FX rate continues to fluctuate, averaging $1.24 since the beginning of 2015 and has recently been trading around $1.20. Because we are investing excess Canadian cash flow in Canadian capital expenditures, there is no real adverse economic impact associated with these fluctuations, but these variances do impact our reported results on a consolidated basis including adjusted EBITDA.

Additionally, even though PAA's first quarter results exceeded guidance by $42 million, we elected not to increase our full year guidance due to a couple of factors. One of the considerations in that decision, which Harry will discuss in his comments, was that our first quarter results included some benefit from timing issues that we expect will balance out over the reminder of the year.

The second and perhaps most important factor is our updated outlook for industry conditions over the balance of the year. With that in mind, I want to take a few minutes to share our thoughts regarding industry challenges that may extend into the first half of 2016.

Let me start off by stating that over the intermediate to long-term, we've remained very constructive, if not flat-out bullish, on the outlook for the North American crude oil industry in general and the mid-stream sector and areas in which PAA operates in particular. The defined crude oil resource base is extensive, the drilling and completion techniques required to recover these resources are proven, and moreover, operators and service companies continue to refine their techniques and practices, lower their cost, and improve their overall efficiency and productivity and thereby lower the commodity price threshold required to support sustained development of this resource.

One final comment on the longer-term is that in order to meet projected worldwide petroleum demand growth, we believe that the world needs the U.S. and Canada to maintain current production levels and over time to grow their production base.

Over the near-term however, we believe the environment is going to be challenging, and with the exception of the few head fakes, could get worse before it gets better. The major consideration in our outlook is the very high inventory levels that have built up and will need to be processed domestically as just one of the many steps necessary to restore balance to the market.

With respect to a market recovery, we have seen a significant reduction in rig count, indications of slowing production growth in certain areas, and actual production declines in other areas. Additionally, we estimate that crude oil refining levels during the coming driving season will remain at high levels and could average around 250,000 barrels per day higher than 2014's record level.

However, compared to the same point in 2014, U.S. crude oil inventories are already 92 million barrels higher and current U.S.

production rates are around 850,000 barrels per day higher again relative to the points last year. The majority of the inventory build-up is located in the Gulf Coast and the Mid-Continent, particularly Cushing, and we believe these areas are reaching practical storage capacity.

Compounding these circumstances, crude oil imports have generally remained relatively consistent with prior year levels, presumably due to quality – crude quality issues and the aggressive pursuit to market share by foreign exporting countries. With a few limited exceptions, the U.S.

does not permit crude oil exports, and thus the only remaining avenue available to reduce crude inventory in the U.S. is through processing.

When viewed collectively, all of these factors suggest to us that high inventory levels will weigh heavily on the front end of the crude oil market structure for the next several months, and depending on world political events and money flows, may very well put pressure on absolute crude oil price levels. Slides five and six provide comparative illustrations of current crude oil inventory, production, import and refinery run levels, and in certain cases, our internal assumptions of activity levels over the next several months.

Slide seven presents an extrapolation of what these assumed inputs project for possible crude oil inventory levels over the balance of 2015 contrasted against actual inventory profiles for each of the last four years. I would also point out that any unexpected downtime at U.S.

refineries or pipelines would only exacerbate this situation. For these reasons, we believe the next several months could be very challenging for the industry.

When we discuss this situation within Plains, the most popular characterization is that something has to give. Potential changes include extended deferrals of refinery turnarounds or directionally similar actions to achieve even higher sustained refinery runs, meaningful reductions in water-borne imports, shut-ins, or rapid declines in North American crude oil production or a meaningful relaxation of crude oil export restrictions.

With the exception of a change in crude oil export rules, the most likely catalyst for the other alternatives involves pressure on North American crude prices or differentials. Additionally, certain of these actions increase the potential for unexpected downtime or upsets.

We believe PAA is relatively well positioned to address many of these potential developments that could evolve out of this situation. However, we are not immune from certain of the potential adverse developments.

Additionally, the data we deal with is imperfect and sometimes delayed, and there are still many unknowns. As a result, it's not possible to identify what exactly will give first, when it will happen, or the magnitude of such developments.

Accordingly, as discussed in past conference calls, our policy in practice is not to incorporate into our guidance the impact of potential market disruptions. In closing, I would note that the guidance we furnished in February was based on an industry environment where the WTI crude price hovered around $50 per barrel.

Although WTI price has risen recently to around $60 or even slightly higher, the year-to-date average for WTI is $50.70 per barrel, and for the reasons I just shared, we continue to incorporate $50 per barrel outlook into our guidance for the balance of the year. With that, I'll turn the call over to Harry to discuss our operating performance for the quarter and our ongoing growth activities.

Thanks, Greg. During my portion of the call, I'll review our first quarter operating results compared to the mid-point of our guidance, the operational assumptions used to generate our second quarter guidance, and provide an update of our 2015 capital program.

As shown on slide eight, adjusted segment profit for the Transportation segment was $246 million, which was in line with the mid-point of our guidance. Tariff volumes of 4.2 million barrels per day were approximately 216,000 barrels a day below our guidance.

That's primarily due to lower than anticipated tariff volumes on both the Basin Pipeline System and our Permian Basin area systems. And I'd like to point out that the physical volumes on the Basin Pipeline were actually higher than anticipated, but the way volumes were nominated resulted in lower than anticipated tariff volumes, so I can best describe the difference by using an example.

The volumes were nominated from a location (11:26) to Midland by a shipper, it's been moved from Midland to Cushing by another shipper, there would be two tariff movements for this volume. On the other hand, if one shipper nominates volumes from (11:38) all the way to Cushing, there would just be one tariff movement.

So in both cases, the same physical volumes would be moved, but in the first case, our tariff volumes are doubled and our tariff revenue would be a little higher. Also, the lower volumes on our Permian Basin area systems were primarily due to weather and inventory builds.

Adjusted segment profit per barrel was $0.64 or $0.02 above the mid-point of our guidance. Revenue was lower partly due to the impact of the Canadian dollar, but this was largely offset by lower operating expenses.

I note that a portion of lower operating expenses is related to timing and will be incurred later in the year. Adjusted segment profit for the Facility segment was $144 million, which was approximately $12 million above the mid-point of our guidance.

Volumes of 124 million barrels of oil equivalent were in line with the mid-point of our guidance. Adjusted segment profit per barrel was $0.39 or $0.04 above the mid-point of our guidance, primarily due to higher than anticipated throughput volumes at our Cushing terminal and lower than forecasted operating expenses in the first quarter.

Again, a portion of these lower operating costs is related to timing. Adjusted segment profit for the Supply & Logistics segment was $231 million or approximately $30 million above the mid-point of our guidance.

Volumes of approximately 1.3 million barrels per day were in line with the mid-point of our guidance. Adjusted segment profit per barrel was $2.03 or $0.25 above the mid-point of our guidance.

The higher than anticipated adjusted segment profit was primarily due to favorable NGL market conditions and then to a lesser extent contango driven crude oil storage opportunities. Let me now move to slide nine and review the operational assumptions used to generate our second quarter 2015 guidance, furnished yesterday.

For our Transportation segment, we expect volumes to average 4.6 million barrels per day, an increase of approximately 426,000 barrels per day from the first quarter. We expect adjusted segment profit per barrel of $0.62 or $0.02 per barrel lower than the first quarter.

The volume increase is due to several factors, including first, the start-up of the Cactus Pipeline and the related impact on our Eagle Ford joint venture pipeline; secondly, the completion of a couple of our expansion projects in the Permian Basin; and third, increasing volumes on the BridgeTex system. And then last, volume increases on leased capacity.

And I'll note that the volumes on the capacity we lease will actually not impact revenue. For our Facility segment, we expect an average capacity of 125 million barrels per month, an increase of 1 million barrels from the first quarter.

Adjusted segment profit per barrel is expected to be $0.35 or $0.04 lower than the first quarter, and the volume increase is attributable to higher than anticipated rail volumes and the segment profit per barrel decrease is driven by the timing of maintenance and integrity management projects. For our Supply & Logistics segment, we expect volumes to average 1.14 million barrels per day or about 132,000 barrels per day lower than volumes realized in the first quarter.

Adjusted segment profit per barrel is expected to be $0.63 or $1.40 per barrel lower than the first quarter. The anticipated volume and segment profit per barrel decreases in this segment from the first quarter reflect the inherent seasonality of our NGL sales volumes and margins.

Let's now move to our capital program. As shown on slide 10, we have increased our 2015 expansion capital plan by approximately $300 million to a revised 2015 target of approximately $2.15 billion.

The increase is a combination of a couple of additional projects I will mention in a couple minutes, and the acceleration from 2016 into 2015 of some of our spending. Slide 11 provides an update on the expected in-service timing of some of our larger projects.

So, let me start with a quick update on the Cactus Pipeline. It began partial operations in April at 50,000 barrels a day.

Committed volumes are anticipated to ramp up to 150,000 barrels a day by August. Our guidance includes volumes of 65,000 barrels a day during the second quarter.

We expect capacity to increase from 250,000 barrels per day to approximately $330,000 barrels per day in the second quarter of 2016 upon the installation of our core point pumps. In the Permian Basin, we have a number of projects we are developing, and we expect to invest approximately $390 million during 2015.

Let me provide a quick update on a couple of these projects. And I'll start with our 24-inch loop of the Basin Pipeline System from Wink to Midland.

Construction has started and the line is expected to be in partial service in the third quarter of this year with full utilization expected in 2016. This line will ultimately add approximately 500,000 barrels a day of takeaway capacity from the Delaware Basin.

In the Delaware Basin, we've also started construction on our 16-inch line from the Barilla Draw area to Wink, and a 20-inch loop of our pipeline system from Blacktip to Wink. Both these lines are expected to be in service in the third quarter of 2015.

Our State Line pipeline is progressing and is expected to be in service in the second quarter of 2016. And before I leave the Permian Basin, I want to point out that we've added new projects since our last call.

Our Luther pipeline, it's a pipeline that will originate in Howard County in the northern portion of the Midland Basin and will connect into our terminal at Colorado City. It's a $50 million project and is expected to be in service in the second quarter of 2016.

In the Eagle Ford, we expect to invest approximately $135 million in 2015. We completed the construction of the segment of our joint venture pipeline from Gardendale to Three Rivers in April of 2015.

Startup of the system will be in June, which coordinates with the volume ramp-up of the Cactus Pipeline. Expansion of the segment of the joint venture line from Three Rivers to Corpus Christi is expected to be in service in August, and upon completion, the joint venture pipeline will have capacity of approximately 600,000 barrels per day.

In addition, the joint venture is building a new 12-inch line that will have the capacity to gather up to 100,000 barrels a day of additional condensate into our station at Three Rivers. Our joint venture marine terminal in Corpus Christi is also proceeding and is expected to begin service in mid-2016.

In the Rockies, we expect to invest approximately $190 million in 2015. During the first quarter, we announced our joint venture with both Magellan and Anadarko to construct the Saddlehorn Pipeline.

The pipeline will originate at DJ Basin and transport crude oil to Cushing with an expected initial capacity of approximately 200,000 barrels per day and an ultimate capacity of up to 400,000 barrels per day. We anticipate the Saddlehorn will be in-service in mid-year 2016.

We are also investing in our Cowboy Pipeline from Cheyenne, Wyoming to our rail loading terminal located in Carr, Colorado. We expect the line to be in service in the third quarter of 2015.

And in the Mid-Continent, we expect to invest approximately $365 million in 2015. Projects include the Diamond Pipeline from Cushing to Memphis, the Red River Pipeline from Cushing to Longview, and the Caddo Pipeline line from Longview to Shreveport, and a 2.2 million barrel expansion of our Cushing terminal.

I'll note that the Caddo Pipeline we have a 50-50 joint venture with Delek, and that the expansion of our Cushing terminal is supported by commitments associated with the new pipelines originating from Cushing. With respect to the Diamond Pipeline, we expect to start construction of the pipeline in the fourth quarter this year and expect the line to be in service in early 2017.

I'll note Valero has an option to acquire at cost a 50% interest in this line. In Canada, we expect to invest approximately $300 million in 2015 with our expansion projects at our Ft.

Sask facility. The expansion includes two new 350,000 barrel spec product caverns, two new ethane caverns with combined capacity of 1.6 million barrels, approximately 5 million barrels of additional brine capacity, a truck rack and a rail loading facility.

In addition, since our last call, we've secured commitments to support the expansion of our Ft. Sask fractionator from 65,000 barrels a day to 85,000 barrels per day and have expanded the scope of the project accordingly.

Shifting to maintenance capital, expenditures for the first quarter totaled $50 million, and was in line with our first quarter guidance. For 2015, we expect maintenance capital to range from $205 million to $225 million.

And before I turn the call over to Al, let me touch on the Capline system. I really don't have much to add to the comments from our last call.

The reversal is still a project. The owners are discussing.

And from a timing standpoint, the pipeline could not be reversed prior to both Diamond and Sandpiper pipelines being placed into service. So, with that, I will turn the call over to Al.

Thanks, Harry. During my portion of the call, I will review our financing activities, capitalization and liquidity, as well as our guidance for the second quarter and full year of 2015.

Our financing activity this quarter included the completion of an overnight equity offering of 21 million limited partner units. The net proceeds of the offering were approximately $1.1 billion.

This transaction was an acceleration of the equity we had planned to issue throughout 2015 under our continuous equity offering program to support our 2015 capital program and to maintain strong financial and liquidity profile. By completing the transaction in the first quarter, we effectively derisked the execution of the targeted equity raise.

And our balance sheet at the end of 2015 will look substantially the same as it would have otherwise. In addition to derisking the equity raise, it also provides significant liquidity and flexibility in the event crude oil markets do get worse before they get better, which is the potential scenario Greg discussed earlier.

As a result of the completion of the offering and an absence of significant acquisition or further expansion in our capital program, we do not anticipate issuing additional units through our continuous equity offering program until later in 2015. As illustrated on slide 12, PAA ended the first quarter with strong capitalization, credit metrics and liquidity.

At March 31, 2015, PAA had a long-term debt to capitalization ratio of 50%, a long-term debt to adjusted EBITDA ratio of 3.8 times, and $4.4 billion of committed liquidity. I would also point out that our long-term debt to adjusted EBITDA ratio would be 3.6 times if adjusted for PAA's cash balance as of March 31, 2015.

Slide 13 summarizes information regarding our short-term debt, hedged inventory and linefill at quarter-end. Moving onto PAA's guidance, which is summarized on slide 14, we are forecasting mid-point adjusted EBITDA of $460 million and $2.325 billion for the second quarter and full-year of 2015, respectively.

Our second quarter forecast reflects the inherent seasonality of our NGL business. As we discussed on last quarter's call, we originally projected a 2015 distribution coverage ratio of approximately one point – or one to one times.

Based on our updated guidance and the 7% distribution growth target, we forecast 2015 distribution coverage of approximately 96%. The slight decrease is primarily a function of the accelerated equity raise I mentioned previously.

Our guidance continues to assume that 2015 oil prices will average approximately $50 per barrel, resulting in suppressed drilling activity throughout the year, and that 2015 exit rate for production will be below 2014 production exit rates. Our guidance for the second quarter only includes favorable market conditions to the extent that we are highly confident that our current activities will capitalize on those conditions with an assumed return to near baseline conditions for our Supply & Logistics segment for the balance of the year, with compressed margins in this low-priced environment, partially offset by some contango storage opportunities.

As Harry mentioned previously, we have increased our 2015 organic capital investment program to $2.15 billion. Nearly all of this capital will be invested in our fee-based Transportation and Facilities segment, and will have minimal contribution to 2015 results, but will provide growth for 2016 and beyond.

This level of investment combined with the $3.1 billion of capital investments we made in 2014 provides us with good visibility for continued multiyear growth, given the time lag associated with achieving full run rate cash flows. For more detailed information on our 2015 guidance, please refer to the Form 8-K furnished yesterday.

Before I turn the call over to Greg, I wanted to note two first quarter accounting items that are included in our selected items. We had losses from derivative activities, net of operating inventory valuation adjustments of $91 million, which are primarily associated with the reversal of gains from 2014.

Additionally, we recorded a downward adjustment totaling $38 million on our long-term inventory. As discussed last quarter, our long-term inventory is comprised of minimum inventory in third-party assets and other working inventory that is needed for our commercial operations and is required for the foreseeable future.

From a business perspective, we consider the long-term inventory to be similar to linefill and do not hedge it, as doing so would create price risk, not eliminate it. As is our standard practice, both of these items were treated as selected items and therefore are not included in our adjusted results.

With that, I'll turn the call back over to Greg.

Thanks, Al. Overall, we're pleased with PAA's first quarter 2015 performance and we also believe PAA is well positioned for intermediate and long-term growth in our fundamental business activities and also for potential market disruptions in the near-term.

The mid-stream assets we are building have very long, useful lives, often 70 years or more. Accordingly, as long as our ultimate assessment of the resource base and the commodity price environment required to develop these resources is directionally on point, near-term production level variances will not materially impact PAA's long-term business or its overall economic returns on capital investments.

As a result of our strong balance sheet, credit metrics that are consistent with or favorable to our targets, and $4.4 billion in committed liquidity, we are well positioned to continue developing our business platform via organic growth projects and to pursue complementary acquisitions. In closing, we remain on track to achieve our goals for 2015, which include delivering on our annual operating and financial guidance and increasing PAA's and PAGP's distribution in 2015 by 7% and 21%, respectively.

Prior to opening up the call for questions, I wanted to mention that we will be holding a joint PAA and PAGP 2015 investor meeting on June 4 in New York. At this meeting, we will share our views on the industry environment for the next several years, discuss our positioning with respect to this environment, and provide a deeper dive into our activities; a more deeper dive than is possible during our quarterly conference calls or our investor conferences.

If you have not received an invitation but would like to attend, please email our Investor Relations team at [email protected]. Thanks for participating in today's call and for your investment in PAA and PAGP.

We're excited about our prospects for the future, and we look forward to updating you on our activities at our investor meeting in June and also on our next call in August. Trisha, at this time, we're ready to open the call up for questions.

Good morning.

Good morning, Brian.

As always, I appreciate the industry color. And I understand your cautious near-term outlook, but given what we've seen in the crude price rally over the past two months, producers recapitalizing lower completion costs, number of drilled but uncompleted wells, I guess, how do you handicap your very conservative outlook for volumes and production growth?

It's certainly a dynamic situation. I mean, we do a roll-up at – starting at really a well level up to a county level all the way up into each of the areas.

And Brian, we have our assessment of what should happen, and in some cases, that's not always what happens. People do drill through uneconomic periods in some cases, and then in other cases, we may find that there are economic wells in an area, but for balance sheet reasons or otherwise, they don't necessarily pursue them.

And then as you mentioned, the DUCs are kind of a big variable in the equation because the rate at which they choose to complete or not complete those can have a fairly big impact on production. I think effectively, if you look at the charts that we shared, we're showing us hitting just under 9.5 million barrels at the peak in 2015 on a total U.S.

basis and exiting the year somewhere between 9 million barrels and 8.9 million barrels. So, let's just call it 8.950 million barrels.

That's about 250,000 barrels a day less than we entered the year, but still about 500,000 barrels a day plus down from the peak. So yeah, I think when you got – had the rig count go down 50%, certainly there's going to be some activity in certain areas that will pick up.

We think the Permian is probably the most resilient of all the areas. Eagle Ford would be next on that list, and of the big three, the Williston would be kind of the last area.

The DJ Basin, by the way, is very economic; probably right up there with the Permian and the Eagle Ford, but it's just not as big. So I think it's – in terms of scale, it's just not as much volume there currently.

Percentage-wise, I think we expect it to continue to increase. So, we roll all that up.

As far as – you certainly mentioned prices – and by the way, we've been wrong a lot of times in the last 30 years. I think we've predicted six of the last four oil price crashes, which means we're not always right, but we're always prepared.

I think – and when we had our Analyst Meeting in June of last year and we said we think oil, which was at that day $102 a barrel, we thought it had to go down to, you know, 40% by, rather quickly, and as soon as we had that conference call – or that Investor Meeting, oil went to $107. So – before it started to fall.

So, I'm not sure I would get too carried away with short-term fluctuations. They – everybody's focused in on weekly data, but the chart that we shared with you suggests that we think ultimately we have to have something give in the overall equation simply because inventory levels are so high right now, we've got to find a way to bleed those off, and the only way you can reduce inventory levels in the U.S.

is to process it. The other – and the way you need to process it is to either import less or produce less or allow us to export.

So, we've given you our view; let's get together in three months and we'll see how the numbers are shaking out.

Yeah, and we'll be getting together sooner at your Analyst Day. In terms of I guess the resiliency of the basins, the Permian is expected to hold up well.

In your guidance for Transportation volumes, did see that come down. Is that more of – from your prior guidance.

Is that more a function of what happened in the first quarter in terms of composition of the nominations, or any additional color on the change in pipeline volumes in your entire Permian Basin system?

Yeah, so, it does incorporate a normalization of the way the volumes have been nominated. So, last year, we saw more of the volumes going from points in the field to Midland and get renominated out of Midland.

Right now, we're seeing more of the volumes being directly nominated through Midland to destination. So, that's probably the biggest driver impacting volumes from our earlier assessment.

We're still bullish on the area. We're still – we've got a lot of pipelines coming into service this year.

And overall, we'll start seeing some volume increases once those lines go into service.

Yeah, I think, Harry, most of it, like on Basin, for example, I mean, we're still showing it pretty full throughout...

Operating at full capacity, yeah.

Okay. And then, on – just lastly for me, given your outlook for production, it seems a little more bearish than some, but you've been adding organic projects to handle barrels – additional volumes.

So I guess, what's your preliminary thoughts on CapEx opportunities? Obviously, some of that money for those projects will be completed in 2016, but what's your general thought on the opportunity set for 2016 for expansion CapEx?

It's again, a dynamic situation. I don't think we're through growing our CapEx budget for 2015 yet.

I think when we announced at the beginning of the year, we said – I think is was $1.850 billion. We're now at $2.15 billion and we've still got several projects, Brian, that we're working on that could add to that.

Most of the adds would be relatively nominal in 2015 relative to what the project would be because it would certainly – starting later in the year, it's going to extend into 2016. So from that standpoint, I'd say we're still pretty optimistic.

We haven't provided any preliminary guidance for 2016 yet, but certainly, I think, and I'm looking at Al, I think it's certainly probably going to be over $1 billion just based upon the extension of, if you will, of the activity that we have going on in 2015 that's initiated in 2015 and carries through. So it's certainly not going to drop off the face of the map, and is probably, you know, meaningfully higher than that $1 billion, but it's a good number.

I would also just want to point out that I think everybody is so focused in on the supply push side of the equation, but there's a rationalization going on in the business right now. You can't have the kind of growth that we've had and not have similar rationalization on the demand pull side of it.

So, if you look at several of the projects that we built, they've been more demand pull than they have supply push. So, the Diamond Pipeline, the Longview pipeline, the extension of the Arcotex piece of it.

So, a lot of things going on out there. I think the important thing for those that aren't familiar with PAA's asset base and business model is, you know, we're kind of covered.

We're not just supply driven, we're not just demand pull, we've got terminals in all the right places, and we've got all the coasts covered as well as into Canada. So, I think we're a relevant part of just any conversation that happens with respect to trying to balance supply and demand.

And then, again, I think long-term, we're very bullish on the resource side of it. We're also pretty optimistic on overall economy and demand growth stabilization, if not growth, and we think ultimately these fast declines of the U.S.

and Canada on these reserves are going to have to require a lot of activity, and that kind of creeps. An area that's been mature is now going to move over to another area and you require more gathering in those areas, and we have the ability to plumb all that together.

So, we will be covering a lot of that on our Analyst Day in June.

Thanks, Greg.

Hi, good morning. I recognize that the change in the guidance was pretty small, but it seems like the Transportation segment took the majority of the hit.

Was there anything going on in that segment outside of the revision to your FX outlook?

There were a few I think timing delays. I think we're running a little bit, you know, weather in South Texas, but it's more just fine-tuning, Steve.

We've moderated the ramp-up with Cactus a little bit, but FX was the largest driver.

And what you – Steve, what you see a little bit is FX is a negative embedded in Transportation and Facilities, and Supply & Logistics, just the way the business is, actually has a little bit of contra to it with parts of the NGL business. So, when you look at a net FX number, it's disproportionate between those segments.

Yeah, I think the net FX amount – we modified our mid-point, you know, the $25 million. I think what Al is saying is effectively FX accounted for almost 100% of that adjustment.

More than 100%.

More than 100%.

Okay.

But in certain segments, it may have been $35 million in one segment and then offsetting to get to that net $25 million.

I'm sorry. That's what I meant by way, yeah.

Yeah.

No, understood. That's helpful.

And a quick follow-up. I recognize it's still early days, but just given the victory of the NDP in Alberta, does that really change your outlook on investment in the region, or just broader energy production?

I don't think we really have much of a different view today than we had before. We're – it really doesn't change much.

Oh. Okay.

That's it from me. Thanks.

Good morning.

Good morning, Jeremy.

Thanks for all the color today. Just wanted to follow-up on the Transportation segment a little bit.

And sorry if I missed it in the prepared remarks, but the other segment seemed to come down a bit quarter-over-quarter. I was wondering if you could help me out there?

I'm not sure I ...

What was the question?

The other segment being?

The other – within all the different volumes that are broken out by pipeline, the other...?

Capacity area? The other...

The other aggregation? Yeah, the volume reductions, that's partly due to the – where we have capacity leases and the volumes were lower, it didn't really affect revenue.

Harry did touch on that in his prepared remarks.

Yeah, so Jeremy, what happens is in certain areas, we have shippers that just lease the whole line and they pay us the same amount whether they ship zero or they ship full capacity, and then we just simply adjust that. So, you'll see some volume adjustments in there that really have no impact on margin.

Okay. Great.

Thanks for that.

And then, if you didn't catch it, just the way volumes are nominated on the basin system, the physical volumes are there, but the nomination mix changes. So, there are less tariff volumes than we originally forecasted, but the physical volumes are still moving.

Okay. Great.

Thanks. And then, Capline came down a little bit quarter-over-quarter.

I was just wondering if you could remind us what's the minimum volumes the pipe can move before it starts to run into operational problems, and do you have any concerns about that?

It's about 300,000 barrels to 350,000 barrels a day total. Keep in mind, we own 54% of that.

So, I think the shipments have been – recently been in the aggregate – Harry, around 350,000 barrels?

350,000 barrels to 400,000 barrels. Marathon has volumes on their space, BP has volumes on their space.

So, even if we have a 54% interest, that doesn't mean we have 54% of the volume. Each owner operates their interest in Capline as if it's a separate pipeline.

So, it operates like there's three pipelines in one physical pipeline.

Okay. Great.

So, at this point, do you see – is there any potential problems operationally speaking with lower volumes?

Well, I think the point that I think everybody's focused in on, Jeremy, is when we activate Diamond pipeline, that's going to take a lot of the volume we're currently shipping on it or that our shippers are shipping on our space off the system, and it's certainly going to take it, we believe, below the 300,000 barrels a day. That's a early 2017 event, and then there's other, as Harry mentioned in his comments, I think Sandpiper is going to affect some of the others shipments on there.

So, I think we're all pressing hard to say that we need to be making decisions today to avoid a problem that's probably going to show up about the first quarter of 2017.

That makes sense. And then, turning over to crude imports, I was wondering if you could expand a bit on thoughts there given the recent increase in the Saudi official selling price to the U.S.

for June, how you see that impacting things?

You know, again, pretty dynamic. Today's numbers just came out, and I think we were down week-to-week probably about 900,000 barrels a day on imports.

But prior to that today's report, it had been running very comparable. In the numbers that we shared with you in the chart, I think we reduced the imports about 100,000 barrels a day on a net basis going forward.

So, that's clearly one of the variables in the equation that we think something has to give. What we have heard in talking directly to some of the larger refineries is that even though inventories have been swelling here, the barrels have been priced to them in a way that's still compelling for them to continue to import, and that's both a combination of both quality adjusted issue as well as just outright flat price.

So, I think what we're hearing is that they're still going to keep pushing for market share. I hear you on the fact that they adjusted their official selling price, but you continue to see their volumes stay stable to go up, and that's the balance we all try to find.

You're trying to find that point in the market where you can raise prices and not impact volumes. And so far, they've been able to do that.

If that starts to go the other direction, we'll probably expect to see an adjustment because we don't see them trying to reduce their volumes. Not in the near-term, anyway.

Okay. Great.

Thanks for the color.

Yeah. Good morning, everybody.

Good morning, John.

Just following-up Jeremy's on Capline, is there anything you can share at this time regarding the study you're undertaking, or is that more of an Analyst Day event, or, you know, maybe any thoughts on that would be helpful.

I think it's a consistently unfolding event where we're making progress in inches when we want to make progress in miles. The – I think what has been said publicly today at a recent conference is that both Plains and Marathon are of one mind that a reversal makes sense.

And – but it still requires all three owners. And so, beyond saying that two of the three owners are holding hands and ready to go forward, there's still a lot of work to do, but conceptually saying, we know it makes sense to reverse the pipeline from our perspective.

We've still got to have the positive vote of that third owner, and that I can't comment on.

Okay. Fair enough.

And then, just kind of coming back to your guidance, obviously we were a little surprised that given the beat, you're effectively – and you're nominally guiding down, so it becomes like a net guide down of somewhere in the ballpark of $60-some million. And so, you're basically saying for $50 crude for the year, things will get materially worse from here and that we should see – revisit sort of a $40-type crude oil price, is the expectation that would occur in the fourth quarter, using your chart seven, given where inventories are that you're going to see a potentially steepening contango at that time, or just help me a little more on putting all these pieces together, because it just – and, yeah, I get it, there's the bias toward conservatism, but it's just – is a little surprising, to be honest.

Yeah, I guess a couple of things. One, and not to try and parse our words too carefully, but our first comment is that we think 92 million barrels of inventory are going to put pressure on the front-end of the curve.

That pressure is going to happen we think whether it's a $60 prompt price or whether it's a $45 prompt price or whether it's a $95 prompt price, because it's a U.S. problem.

If you think about it, the only way that we can get that inventory down is to process through the refinery more production or more volumes than we're importing and producing. And right now, we're thinking volumes that you can process are probably going to average 250,000 barrels a day higher this year than last year.

If imports are relatively unchanged and production's up 850,000 barrels a day and we're 92 million barrels a day already higher in inventory, something's got to give. And so, are we cautious about the second half of the year or the remainder of the year?

Absolutely. Do we know what price it's going to be?

We don't. We think we have a feeling that the structure is going to have pressure on the front-end of the curve, and if everybody declares victory and says we've seen the bottom and we're going to start raising volumes again, they're only going to exacerbate the problem because even if we had in the scenario that I gave you, a million barrels a day higher demand in the U.S.

than what we're counting on, you can only process what the refineries can push through right now. So, that doesn't change the equation.

So, yeah, we're probably in the cautious, if not bearish, camp for the next nine months. And again, we're the outlier, I think.

We were the outlier last year when we said we think oil at $102 has got to go to $65. We were right about the direction, we were wrong about the street address.

It went through $65 on its way to $45. So, money flows can change a lot of things and I know it makes everybody feel good, but fundamentally, you have to get rid of 92 million barrels.

I mean, we're at all-time highs for the last 70 years or 80 years, John.

Yeah.

How do you solve that? And if you have too many winter coats and it starts going into summer season, generally the way you get rid of them is you discount that price.

Yeah.

Hey, John, and I would add one thing. You characterized the guide down of $60-some million, and you might not have – and we didn't give a specific number on it, but a material part of the overperformance and one key was timing that will balance out.

So, I think – I don't think characterizing that the guide down in the back nine is $67 million. We sure don't think of it that way.

And then, clearly, a part of that is FX.

Which has no net economic impact; it just reflects our reported numbers.

Okay. Yeah, that's definitely a fair point on that.

So, all right, well, that's – I mean, that's helpful. I mean, I definitely agree something has to give.

I think we're all in that same camp. But, anyway.

So, I appreciate it. Thank you very much.

Thanks, John.

Hi. Good morning, guys.

Good morning, Sunil.

A couple of questions for me. First, when I look at your Supply & Logistics segment, and specifically NGL volumes, can you remind us how much of those NGL volumes come from your Canadian assets?

The whole business is run out of our Calgary office.

Oh, okay.

So, most of the volume generates there, but they're opportunistic.

So, a lot of the supply side is coming out of the Canadian side of it. On the sales side of it, Sunil, it's a combination of Canadian and U.S.

markets. And of course, we have a lot of – if you look at our map, we have a lot of storage assets throughout the U.S., you know, Arizona, Carolinas, Michigan.

So it's really responsive to market changing demands, and with the railcars and our pipeline systems and the inventory that we have, we're able pretty much to respond to all that.

Okay. That's helpful.

And then, just a little bit broader question in terms of your new capital that you're putting to work. I was kind of curious, specifically if you look at the Saddlehorn project, how do you look at economics on these projects, especially since you may be taking some capacity on these pipeline projects through your marketing segment, Supply & Logistics segment?

It varies by area in terms of what kind of return we're prepared to move forward with. In some cases, for example, in the Permian, we always love to have commitments, but if we're absolutely convinced that the resource potential is there and that it's a question of not if, but when, and we think we can maintain a strong competitive advantage, in some cases, we build pipelines before we have the commitments.

In the case of the Saddlehorn, we think that's going to be a fairly well-serviced area because we think that there's probably more pipeline capacity slated to be built out of there than there is supply. And in that particular case, we have commitments from the two largest producers in the area.

And then as you say, we actually supply – can supply a lot of the pipeline shipment as well through our activities where we purchase from other producers and therefore control that barrel and determine which pipeline it goes on. So, there we're making sure that we have a minimum rate of return that allows us to cover our cost of capital plus what we would think is the execution risk with that stage of it.

Clearly, if incremental volumes, if you're only meeting 40% to 50% of your total capacity, an incremental 10% or 15% capacity utilization will drive those returns up very, very high. But again, in certain areas, it's going to be very competitive.

So, it really varies which part of the U.S. that you're in.

I will say that we have the ability because of the interconnectivity of our system to view things on a consolidated basis that says individually a pipeline project by itself, if somebody else was going to build it, they might not be able to make an acceptable rate of return. But when you look at it holistically as to we're connecting pipeline A to pipeline C, D, E and F and into our storage facilities and building capacity there and getting a return we can actually make, that's part of the competitive advantage of having a network.

Yeah, no, that's very helpful. And just one clarification on Saddlehorn.

So the two commitments that you mentioned, those are on the pipeline volumes. In terms of your Supply & Logistics, do you have acreage dedications also in that area?

We have long-term contracts within our Supply & Logistics segment. So, we're pretty active in the area.

We've got volumes we can bring to the pipeline.

Okay. That's helpful.

And then, just one last one from me. In terms of the M&A environment, where do you think we are in terms of that cycle?

And do you think that with this anticipated correction in crude pricing to clear inventory, do you expect – or do you have any sense of the timing on the M&A activity?

I think we mentioned on our last conference call that we expected consolidation activity to pick up in the mid- to latter part of this year after the companies digested what's happened. First, figured out what the impact is on their business, and then potentially what the impact is on other people's businesses, and it could be a fairly lengthy process if there is really a consolidation of the sector.

And I don't think anybody – I'm looking around, and I don't think anybody's views have changed at all.

Yeah, I would say that if you go back and you look at the slide that we had again from our Analyst Day where we said here's what we think we're preparing for in the future, if you said which box can we not check or which box were we just wrong on so far, is that the capital markets really haven't withdrawn capital from the industry. I mean, they're – people are raising capital at rates, certainly on the upstream part of it, they've raised more money I think in the first five months in $50 oil than they did all of last year at $100 oil.

The same thing is directionally, maybe not that same precise calculation, but directionally true on the mid-stream and so, as long as competitors that might be struggling otherwise still have access to capital, it's probably going to stretch out the acquisition and consolidation cycle longer. So we just missed that analysis.

We would have thought with the outlook for lower accretion across the board, in some cases, companies having trouble not only making their growth but making their current distribution would probably cause capital to be withdrawn or certainly withheld from the market. It hasn't happened.

So, to the extent that continues, I think everything John said is true, but it's probably stretched out even farther to the right.

Okay, guys. Thanks.

Your commentary is really helpful.

Thanks for taking the call. I was wondering if you would care to comment on the disappearance of the contango trade almost as fast as it appeared?

It's still there today. I mean, it's pretty dynamic.

We internally, James, have referred to it as an accordion feature, and I give our guys credit that are in our commercial group. There's a lot of things that happen in infrastructure limitations, market limitations, and money flows can change all of those.

What we've seen is over time fundamentally we're still 92 million barrels higher in inventory. And a lot of that inventory we believe that's being stored is like sweet crude.

That's not what the market really has the highest demand for. So, I would suggest you just stay tuned.

Okay.

We're still a dollar contango. I mean, it's still a dollar contango, so it's...

I don't know if it's (56:54).

And if you could comment on – we were a little surprised to see Enterprise entering the Permian direct to Houston crude market. I was wondering if that surprised you, and what the implications of that are for you guys and other Plains Pipeline – and other pipelines from the Permian towards the East?

I wouldn't say we were surprised. I think we're only disappointed that we don't get 100% of market share.

But I think if you drill down into that transaction, from what we understand – and it's just a recent development that – with the facts that are out there, but I mean, it's part of the quality segregation issue. I mean, that's a dedicated condensate line, I believe.

(57:42)?

Yeah, they're actually going to move four grades. And that pipeline has been in the works for long time, those discussions.

So, we were not surprised about it, but like Greg said, we'd love to be in every pipeline.

Yeah, I think what it indicates, James, a little bit is the confidence that the producers have in the resource base in the Permian and the need long-term for markets. Again, I think everybody focuses in on the next 12 months, 15 months, even 24 months, these are assets that are going to be there 70 years, 100 years, long after you and I are off the face of this earth, and so, it's really a long-term balancing issue, not a short-term issue.

And I think the other thing that, from our system, our footprint in the Permian Basin is really a huge gathering footprint, and if you see all – we've got three projects in the Delaware Basin that are aggregating crude bringing into Midland and Colorado City that will source all these takeaway pipes even – we're not an owner in the takeaway pipes, but our footprint is really in the gathering and bringing it to the aggregation hubs.

Okay. Thank you.

Thank you. Trisha, I think we've got time for one more call – question.

Hey, good morning, guys.

Good morning.

Just had a quick question regarding rail volume. It looks like your revised guidance for the year is down considerably from guidance issued in February.

Is that something that – is that just an effectively a map over from lower 1Q volumes for the balance of the year, or is there any other noise expecting those full-year average volumes?

It's mainly the impact of Q1. There's...

We adjusted timing a little bit.

Adjusted timing, yeah, our Canadian facility is probably going to come in a little later than we'd originally had in Q1. And there's been some downtime in California because of the refinery explosion that happened.

So, the timing of the ramp up of that, those volumes have been impact a little bit. So, those are probably the drivers of the rail volumes.

Okay. And then just one quick follow-up, if you don't mind.

I heard some recent rumbling from the EPA regarding your Bakersfield facility. Can you comment on any of that, or do you expect whatever the outcome could be any material impact on any financial or operating measures out of that terminal?

It's a recent development, and in fact, there were reports in the press before we were actually even provided notification from the EPA. So, you can kind of draw your own conclusions about who has the in on information flow out there, the activists or the companies that operate.

But there, just to be clear, it's a responsibility that was delegated from the EPA as we understand it to the San Jacinto – San Joaquin Valley air quality board there, and we've got all the permits. We believe we fully complied with all those regulatory requirements, and we understand the San Joaquin Valley Air Pollution Control District, where we got the permits from, agrees with us and that they believe that the EPA is just wrong.

That said, this has just happened, and we haven't even had a chance to meet with the EPA. So, we really can't comment beyond that, other than the fact, I believe that San Joaquin Valley Air Pollution Control District has come out publicly and said that they believe we're right and the EPA is wrong.

So...

It sounds like – a little bit like a turf war.

Thanks, guys. That's it for me.

Thank you. Trisha, I think we're done here.